Method of reducing c5 and lighter hydrocarbons in reformer feed



May 21, 1968 s. G. GRECO 3,384,576

METHOD OF REDUCING C5 AND LIGHTER HYDROCARBONS IN REFORMER FEED BY Saver/'0 G. 6mm

Affomey Nophtho May 21, 1968 s. G. GRECO 3,384,576

METHOD DE REDUCING c5 AND LIGHTER v HYDRocARBoNs 1N EEFORMER FEED Filed March l, 1967 2 Sheets-Sheet 2 FIGURE 2 INVENTOR- Y Saver/0 G. Greco B /MZM A Homey i l United States Patent O 3,384,576 METHOD F REDUCING C5 AND LIGHTER HYDROCARBONS IN REFORMER FEED Saverio G. Greco, Valhalla, NY., assignor to Mobil Oil Corporation, a corporation of New York Filed Mar. 1, i967, Ser. No. 619,781 6 Claims. (Cl. 20S-361) ABSTRACT OF THE DISCLOSURE A naphtha which has been previously treated with hydrogen to reduce sulfur and nitrogen concentrations to innocuous levels is treated to reduce concentrations of materials boiling at C and below. The hydrogen treated naphtha is directed to an initial flash unit to separate vaporous material from liquid naphtha. Vaporous material is further separated from liquid naphtha by a series of steps comprising a stripping step .and a plurality of flash steps.

BACKGROUND OF THE INVENTION (a) Feld of invention At the present time, Straight run naphtha is reformed in the presence of platinum type catalyst to improve its octane characteristics. The straight run naphtha usually contains contaminants such as sulfur and nitrogen compounds at undesirably high levels. It is desirable to reduce the sulfur, nitrogen and water concentrations in the naphtha prior to reforming to thereby increase reforming catalyst life. Presently, sulfur and nitrogen concentrations in naphtha are reduced by .a mild` hydrogen treatment wherein the organic sulfur and nitrogen compounds are converted to hydrogen sulfide and ammonia while minimizing cracking reactions. The hydrogen sulfide and ammonia are then removed from the naphtha prior to the naphtha reforming step. Even when the reforming step is conducted under conditions which include sulfide addition and/ or ammonia addition with certain types of naphthas it is desirable to initially reduce the sulfur and nitrogen concentrations in the naphtha to innocuous levels. In this manner, `a base value is established which permits accurate control for the sulfide and/or ammonia addition to the reformerfs).

It is also desirable to remove C5 and lighter hydrocarbons from the reformer feed. Those skilled in the art of reforming naphtha to obtain reformate having yan improved octane rating recognize that the octane ratings of most of the C5 and lighter hydrocarbons in naphtha cannot be improved by reforming. Furthermore, the presence of C5 and lighter hydrocarbons in a reforming reactor reduces the purity of the hydrogen-rich recycle gas which reduces the hydrogen partial pressure of the recycle gas. This reduced hydrogen partial pressure increases coke laydown on the platinum reforming catalyst and thereby undesirably increases the catalyst aging rate.

(b) Description of prior art In -many pres-ent reforming operations the effluent from the naphtha hydrotreating step is -directed to a flash zone wherein the majority of the gaseous hydrogen sulfide and ammonia are separated from the liquid naphtha. The liquid naphtha is then directed to a stripping step wherein it is contacted with a stripping gas, usually excess reformer off-gas to remove the remainder of the hydrogen sulfide and ammonia from the liquid naphtha. The liquid naphtha is then directed to the reformer operation. It is desirable to employ the excess reformer off-gas in the stripping step since it is readily available and is relatively inert with respect to the naphtha at normal stripping conditions. The reformer off-gas, even after be- Patented May 2l, 1968 ing employed in the stripping step, also can be readily employed in the naphtha hydrotreating step to convert the contaminants in the naphtha to hydrogen sulfide and ammonia. In addition, when employing excess reformer off-gas when the reformer is operated under desiccated conditions, very efficient removal of water from the naphtha can be obtained in the stripping step. Thus, operating in this manner permits efficient use of excess reformer off-gas while minimizing the need for outside sources of gas, especially hydrogen gas, for the pretreaterreformer operation.

Unfortunately, when employing a stripping step to effect relatively complete water, hydrogen sulfide, and ammonia removal, the hydrocarbon portion of the stripping gas from the reformer is dissolved in the naphtha at stripping conditions. As mentioned above, this is disadvantageous from the standpoint of reformer catalyst aging. Furthermore, the presence -of C5 and lighter hydrocarbons in the reformer increases the molecular weight of the reformer recycle gas and thereby necessitates an undesirable increase in compressor capacity for the reformer Irecycle gas stream. To alleviate these disadvantages, it has been proposed to employ a depentanizer to replace the stripper in order to effect relatively complete removal of hydrogen sulfide and ammonia ras well as C5 and lighter hydrocarbons from the hydrotreated naphtha prior to reforming. Although a depentanizer effects relativ-ely complete removal of the undesired portions from the hydrotreated naphtha, ya greatly increased naphtha separation cost7 as compared to a stripper is introduced. A depentanizer contains approximately twenty trays more than that employed in a normal stripper. Furthermore, a ydepentanizer employs means for cooling and refluxing the vaporous components from the fractionating section and heating and refluxing the liquid from the stripping section. This increased amount of apparatus and apparatus complexity increases both initial cost and operating cost of separation as compared to a stripper.

SUMMARY OF THE INVENTION Briefly, the present invention provides for flashing, in a first flashing step, the effluent of a mild hydrogenation reactor at a pressure slightly lower than the hydrogenation reaction pressure and at temperatures in the range of about F. to about 120 F. to separate vaporous material containing high concentrations of hydrogen sulfide and hydrogen from liquid naphtha. The liquid naphtha from the flash drum is reheated in any suitable manner to a temperature in the range of from about F. to about 350 F. preferably from about 250 F. to about 325 F. and thereafter the heated naphtha is directed to a stripper to reduce the amount of readily vaporizable material in the naphtha including hydrogen, gaseous hydrocarbons and hydrogen sulde, The gaseous stripping medium comprises excess hydrogen rich reformer off-gas. The effluent liquid from the stripper is directed to a plurality of flash steps in series to effect further separation. Preferably two flash steps are employed. From lthe stripper, the liquid naphtha is directed to a second flash step wherein the pressure is maintained at least three hundred pounds per square inch (300 p.s.i.) less than the pressure maintained in the stripper, In the second flash drum, C5 and lighter hydrocarbons are volatile while some C5 and heavier hydrocarbons are carried with the lighter hydrocarbons. The flash vapor from the second flash step is cooled to a temperature in the range of from about 75 F. to about 100 F. to condense the major portion of the C5 and heavier hydrocarbons. The cooled mixture of liquid and vapor is directed to a third flash step wherein the pressure is maintained at about the same or 3. ten to twenty pounds per square inch lower than the pressure in the second flash drum. The hydrocarbons condensed in the third flash step are combined with the liquid hydrocarbons flowing from the second flash step to provide the feed to the reforming unit containing a reduced concentration of C and lighter hydrocarbons.

By the process of this invention, sulfur and nitrogen contaminants as well as the majority of C5 and lighter hydrocarbons are removed from the hydrotreated naphtha prior to reforming. This is accomplished without resorting to expensive separating apparatus or excessive separation operating costs. The process of thisrinvention is particularly useful in a dual reforming process wherein low boiling naphtha and high boiling naphtha are separately reformed. The high boiling naphtha usually has an initial boiling point of from about 250 F to about 300 F. and an end boiling point up to about 400 F. Most existing refineries contain a high pressure pretreater and reformer which reforms a full range naphtha. When a refinery requires increased reforming capacity, it is often attractive to build a low pressure reformer to reform the lighter naphtha portion of the full range naphtha. This requires a distillation column to split the full range naphtha into a light naphtha charge to the low pressure reformer and a heavy naphtha charge to the existing high pressure reformer. Advantages include improved quality gasoline and more flexibility.

Flashing the stripper bottoms from a high pressure pretreater stripper tower containing heavy naphtha is advantageous since the absorbed light hydrocarbon flash easily from the heavy naphtha due to the widedifference in volatility.` Hence, the flashed vapor contains only a very small amount of CG-tnaphtha.

BRIEF DESCRIPTION OF THE DRAWINGS FIGURE 1 is a flow sheet illustrative of the present invention including the hydrogen treating step and the series of sparation steps subsequently employed in this invention.

FIGURE 2 shows a preferred means for accomplishing the initial flashing of the naphtha effluent from the stripper.

DESCRIPTION OF SPECIFIC EMBODIMENTS Referring to FIGURE l, naphtha for example, having a boiling range of 250 F. to 365 F. ASTM flows through pipe 11 from a source not shown to the suction side of n'aphtha pump 12. Pump 12 discharges the naphtha into pipe 13 through which the naphtha flows to heat exchanger 14 where the naphtha is in indirect heat exchange with the effluent of hydrotreating reactor 20 flowing therefrom through conduit 21. From the indirect heat exchanger 14, the naphtha flows through pipe 15 to coil 16 in furnace 17. In coil 16, the naphtha is heated to a hydrodesulfurizing or hydrodenitrogenizing temperature in the range of about 600 to about 750 F. (Hydrodesulfurization and hydrodenitrogenization are both exothermic reactions.) From coil 16, the heated naphtha flows through pipe 18.

Hydrogen-containing gas which contains hydrogen sulfide from stripper 38 flows through conduits 39 and 19 where it mixes with the heated naphtha at the rate of at least 600 standard cubic feet of hydrogen per barrel of naphtha to form a charge mixture. The charge mixture enters the hydrotreating reactor 20 at a temperature in the range of about 600 to about 750 F.

The hydrotreating reactor is charged with any suitable particle-form solid catalyst having hydrodesulfurizing and/or hydrodenitrogenizing capabilities such as a mixture of oxides of cobalt and molybdenum on alumina and nickel-tungsten suldes per se or on alumina. Presently, it is preferred to use a mixture of oxides of cobalt and molybdenum having the aforesaid capabilities.

The charge mixture flows downwardly' through the catalyst to the outlet of reactor' 20. The reactor effluent flows through conduit 21 to heat exchanger 14 thence through conduit 22 to heat exchanger 23. In heat exchanger 23, the reactor eflluent is in indirect heat exchange with liquid hydrocarbons flowing from high pressure flash drum (HP. flash drum) 27. From heat exchanger 23, the reactor effluent flows through conduit 24 to cooler 25. In cooler 25 the reactor effluent at a pressure less than that of the reactor due to friction of intervening piping is cooled to a temperature at which C4 and heavier hydrocarbons are liquid at the existing pressure, eg., to 120 F. while the hydrogen sulfide and/ or ammonia are volatile. Water is also condensed containing hydrogen sulfide.

The uncondensed reactor eflluent flows from high pressu-re flash drum (HP. flash drum) 27 through conduit 28 to hydrogen sulfide recovery and/or use as fuel, or further processing not shown. The water condensed in H.P. flash drum 27 flows through pipe 29 to a sour water stripper not shown. The condensed hydrocarbons, i.e. C4 and heavier together with hydrogen and hydrogen sulfide dissolved therein flow from H.P. flash drum 27 through pipe 36 to indirect heat exchanger 23 and thence through pipe 31 to the suction side of pump 32. From pump 32, the HP. flash drum hydrocarbons comprising C4 and heavier hydrocarbons, hydrogen and hydrogen sulfide flow through pipe 33 to indirect heat exchanger 34 where the HP. flash drum hydrocarbons are indirectly heated in any suitable manner as for example by the hydrotreater reactor eflluent to a temperature in the range of about 300 to about 375 F., the heating medium entering heat exchanger 34 through pipe 35 and leaving by pipe 36.

From heater 34 the H.P. flash drum hydrocarbons (C4-H flow through pipe 37 to stripper 38. Stripper 38 is operated at a pressure in the range of about 400 to about 500 p.s.i.g. at a temperature in the range of about 250 F. to about 325 F. In stripper 3S, naphtha is countercurrently contacted with excess reformer off-gas entering through conduit 50 from a reforming reactor not shown. The hydrogen and hydrogen sulfide comprising the overheat of stripper 38 flows through conduits 39 and 19 to the hydrotreater reactor 20. The bot-toms of stripper 38 comprising C1 and heavier hydrocarbons flows therefrom through pipe 40 under control of expansion valve 41 to primary low pressure flash drum (PLP flash drum) 42. The pressure in PLP flash drum 42 is at least 350 pounds per square inch less than that of stripper 38 and in the range of about slightly above atmospheric to about pounds per square inch absolute. When it is desired to employ the vapors as fuel, the pressure in flash d-rum 42 is maintained at from about 60 p.s.i.a. to about 120 p.s.i.a. to permit vapor flow from the flash drum to the burner not shown. The temperature in PLP flash drum 42 is correlated with the pressure therein to ensure that a maximum of the C5 and lighter hydrocarbons in the stripper bottoms are volatile at a pressure of 100 p.s.i.a. Ternpe-ratures in the range of about 275 to about 315 F. can be employed in flash drum 42.

The hydrocarbons volatilized in PLP flash drum 42, primarily C5 and lighter but containing some C6 and heavier, i.e., PLP overhead flow at reduced temperature, due to the volatilization in PLP flash drum 42, through pipe 43 to cooler 51 wherein it is cooled to a temperature of between about 75 F. and about 120 F. From cooler 51, the overhead flows through conduit 52 to secondary low pressure flash drum 44. In SLP flash drum 44 the pressure and temperature are -regulated to condense C6 and heavier hydrocarbons. The uncondensed components of the PLP overhead flow from SLP flash drum 44 through pipe 45 to hydrogen recovery, C4 and C5 recovery, a fuel gas system, or other processes, as desired.

The condensed hydrocarbons of the PLP overhead flows from SLP flash drum 44 through pipe 47 to pipe 46 where the condensed hydrocarbons or SLP bottoms mix with the bottoms of PLP flash drum flowing therefrom through `pipe 46. The mixed PLP flash drum and SLP flash drum bottoms forni the reformer unit feed. The reformer unit feed contains at least fifty percent Stripper PLP SLP 38 Flash Drum Flash Drum A. Pressure, p.s.i.a. 493 100 Q0 Temperature, F 281 277 100 B. Pressure, p.s.i.a 492 100 E'O Temperature, F 319 315 100 Referring now to FIGURE 2, naphtha from the stripper which contains some dissolved C5 and lower hydrocarbons are directed through conduit 60 into the interior of flash drum 42. The incoming naphtha contacts deflection baie 62 and is splashed downwardly to the liquid in settling zone 64. Splashing the incoming naphtha assists in separating the vapor from the liquid. The liquid passes from settiing zone 64 through coalescer 66. Coalescer 66 comprises a housing 68 which contains high surface area wire mesh and produces larger sized vapor bubbles as the liquid is passed therethrough. After passing through the coalescer 66, the liquid contacts a weir 70 and is caused to move upwardly. The weir '70 is at an engle with the horizontal usually between 45 and 60. The liquid level in pumpout zone 72 is maintained below that of the settling chamber 54. Thus the liquid is caused to flow upwardly on one side of the weir 70, and downwardly on the opposite side of the Weir. This liquid ilow over the weir promotes upward vapor flow and thus assists in separating the vapor from the liquid. The liquid is pumped out of the flash drum 42 through conduit 74. The vapor passes upwardly into vapor zone 76 and out of the ash drum 42 through conduit 78. A vortex breaker -80 is provided at the liquid outlet of the flash drum 42 to prevent vortex formation and thus prevent mixing of vapor and liquid. The liquid level in pumpout zone 72 is maintained at the desired low level by a level control means 82 which is associated with valve 86 and which is responsive to level measuring means 84. Level measuring means 84 comprises a standpipe having a float therein. The iloat activates or deactivates a level control 82 which in turn opens or closes valve 86 responsive to the level in pumpout zone F 72. The level control 82 and valve I86 can be activated pneumatically, electrically or mechanically.

The process of this invention can be used to treat naphthas boiling within the range of C6 to 400 F. It is preferred to treat a high boiling naphtha boiling within the range of from about 250 F. to about 400 F. When treating a high boiling range naphtha, more complete separation of the stripped naphtha is obtained in the nal flash steps due to the relatively high volatility difference between the naphtha and the C5 and lighter hydrocarbons. Thus the present invention is particularly useful when employed in combination with a dual reforming process wherein high boiling naphtha and low boiling naphtha are separately reformed.

Furlther, it is preferred to employ the process of the present invention in combination with a desiccated reforming process such as described and claimed in U.S. Patent 3,234,120 issued Feb. 8, 1966 which is incorporated herein by reference. In a desiccated reforming operation, the excess reformer oit-gas has an extremely small concentration of water since the off-gas is contacted with an adsorbent such as 4A sodium crystailine aluminosilicate, to remove the water therefrom. Since the reformer off-gas in a dry state has a greater capacity for water, it effects removal of water from the naphtha prior to reforming as well as stripping the naphtha of hydrogen sulfide. By removing water from the naphtha in the stripping step, the need for a separate naphtha drying step to effect desiccated reforming conditions is materially reduced or eliminated.

The condtions of temperature and pressure in each of the dash steps are maintained so as to maximize separation of C5 and lighter boiling materials from C6 and heavier naphtha. In addition, the pressure in the Hash steps are maintained so as to permit ow of naphtha from the hydrotreating step to the reformer without the use of excess pumping power. In the first flashing step subsequent the hydrotreating step, temperature is maintained within the range of about F. to about 120 F. while pressure is maintained within the range of about 200 p.s.i.g., to about 600 p.s.i.g. In the stripping step, temperature is maintained within the range of about 100 F. to about 350 F. while pressure is maintained within the range of about 250 p.s.i.g. to about 650 p.s.i.g. Pressure in the first flash step subsequent to the stripping step is maintained between about l0 p.s.i.g. and 100 p.s.i.g. while temperature is maintained between about 100 F. and about 350 F. Pressure in the second ash step subsequent the stripping step is maintained between about 0 p.s.i.g. and 90 p.s.i.g. while temperature is maintained between about 75 F. and about 100 F.

What is claimed is:

1. The process for separating components boiling at C5 and below from a hydrogenated naphtha which comprises;

(a) flashing a hydrogenated naphtha at a temperature of from about 75 F. to about 120 F. to separate hydrogen rich gas from liquid naphtha,

(b) heating the liquid naphtha to a temperature of from about F. to about 350 F.,

(c) stripping the heated naphtha with hydrogen rich off-gas to separate hydrogen, hydrogen sulfide, and ammonia from the liquid naphtha,

(d) flashing the stripped liquid naphtha in a second flash step to separate vaporous material boiling at C5 and below from liquid naphtha,

(e) cooling the vaporous material from step (d) to a temperature of between about 75 F. and about 100 F., and

(f) flashing the cooled vapor from step (e) to separate vaporous material boiling at C5 and below from liquid naphtha.

2. The process of claim l, wherein the liquid naphtha within the Hash step (d) is passed through a coalescing medium and subsequently from a first zone of relatively high liquid level to a second zone having a liquid level lower than said first zone.

3. The process of claim 1 wherein the hydrogen rich gas in step (c) is obtained from a downstream reforming step.

4. The process of claim 1 wherein the hydrogen rich gas from step (c) is directed to an upstream naphtha hydrogenation step.

5. The process of claim 1 wherein the temperature in the stripping step (c) is maintained between about 250 F. and 325 F.

6. The process of claim 1 wherein the naphtha to be hydrogenated has an initial boiling point of from about 250 F. to about 300 F.

No references cited.

HERBERT LEVINE, Primary Examiner. 

